In-Situ System Calibration

ABSTRACT

A method for re-calibrating installed downhole sensors used in hydrocarbon wells by the application of a calibration string inserted in the wells and deployed in close proximity to the installed downhole sensor.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. application Ser. No. 13/751,056filed Jan. 26, 2013.

BACKGROUND

Fiber-optic sensors are increasingly being used as devices for sensingsome quantity, typically temperature or mechanical strain, but sometimesalso displacements, vibrations, pressure, acceleration, rotations, orconcentrations of chemical species. The general principle of suchdevices is that light from a laser is sent through an optical fiber andthere experiences subtle changes of its parameters either in the fiberor in one or several fiber Bragg gratings and then reaches a detectorarrangement which measures these changes.

The growing interest in fiber optic sensors is due to a number ofinherent advantages:

-   -   Inherently safer operation (no electrical sparks)    -   Immunity from EMI (electromagnetic interference)    -   Chemical passivity (not subject to corrosion)    -   Wide operating temperature range (wider than most electronic        devices)    -   Electrically insulating (can be used in high voltage        environment)

Fiber optic sensors deployed in wells are predominately calibratedbefore being deployed down hole. After calibration such sensors areoften permanently installed behind a well casing or they are attached tothe downhole tubing. As downhole conditions change over time, some ofthese installed sensors may experience high temperatures, high pressuresand various chemicals that may impact the installed sensor performance.

The sensor itself will often get calibration coefficients that areunique to the sensor, and these calibration coefficients are used in theinterrogation unit to achieve desired accuracy and resolution. Manysensors must periodically be calibrated due to component drift either inthe sensor itself or the interrogation unit. In some cases, it isbeneficial to calibrate the sensor and the interrogation unit as a pair.Sensors permanently installed in oil & gas wells cannot be removed forcalibration, and estimated annual drift requirements are applied to thesensing system.

There are economic advantages to having a method for re-calibrating suchdown-hole sensors. For example DTS systems are usually calibrated witheach fiber during or prior to deployment. To replace a DTS system whereyou have up to 16 sensing fibers/wells connected would be a challengingtask due to the calibration. The method proposed herein would allowin-situ calibration of the DTS system and the sensing fiber in case theDTS system or the fiber would need to be replaced.

Thus a need exists for ways to re-calibrate downhole sensing systemsin-situ, without having to remove the sensors from the downholeenvironment.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing issues are at least partly addressed by the disclosed bythe In-Situ System Calibration as illustrated in the drawings. Thedrawings are not strictly to scale because the calibration strings maybe only 1-2 inches in diameter while casings may be as small as 4 inchesin diameter up to more than 16 inches.

FIG. 1( a) is an illustration of a calibration string for calibration ofa chemical sensor.

FIG. 1( b) is an illustration of an alternate embodiment of acalibration string for calibration of a chemical sensor.

FIG. 2 is an illustration of a calibration string for calibration of astrain sensor.

FIG. 3 is an illustration of a calibration string for calibration of apressure sensor.

FIG. 4 is an illustration of a double ended conduit with a permanentlyinstalled optical fiber. The calibration string for calibration of aDistributed Temperature Sensing (DTS) sensor may be inserted in theright side tube (440).

FIG. 5 is an illustration of a calibration string for calibration of aDistributed Acoustic Sensing (DAS) sensor.

FIG. 6 is an illustration of a calibration string for calibration of aseismic sensor.

FIG. 7 is an illustration of a calibration string for calibration of anelectromagnetic sensing sensor.

DETAILED DESCRIPTION

In the following detailed description, reference is made that illustrateembodiments of the present disclosure. These embodiments are describedin sufficient detail to enable a person of ordinary skill in the art topractice these embodiments without undue experimentation. It should beunderstood, however, that the embodiments and examples described hereinare given by way of illustration only, and not by way of limitation.Various substitutions, modifications, additions, and rearrangements maybe made that remain potential applications of the disclosed techniques.Therefore, the description that follows is not to be taken as limitingon the scope of the appended claims.

Modern fiber optic sensors are today being used in wells to sense manydifferent parameters including at least temperature, pressure, strain,acoustic, seismic, electromagnetic, and chemical. All of these sensorsare calibrated prior to installation, and permanently installed behindcasing or attached to down-hole tubing. Even in ideal conditionsinstalled sensors must periodically be calibrated due to component drifteither in the sensor itself or the interrogation unit. As down-holeconditions change over time, some of these installed sensors mayexperience high temperatures, high pressures and various chemicals thatmay impact the sensor performance and increase the need forre-calibration.

In the description to follow a method is proposed to re-calibratein-situ installed sensors by in each case inserting in-siturecalibration devices which are usually calibration strings associatedwith the particular installed sensors and inserted in the well close tothose sensors. The calibration string can be permanently installed inthe well, or it can be inserted for a temporary logging operation. Foreach type of sensing system to be described the calibration string isspecifically associated with the installed sensor system. Theembodiments will be described in a series of examples. The termcalibration string, as used in this description might be an insertedtube, such as a coiled tube, that encloses the recalibration apparatusneeded to recalibrate the particular sensor that is installed in thewell and may need occasional recalibration. The term recalibrationstring can also be a mechanical structure inserted downhole without needof any tubing.

EXAMPLE 1

A chemical installed sensor is commonly impacted by repeated exposure todown-hole chemicals such as for example wax, asphaltene or otherchemical commonly present down hole. These chemicals may build up layerson top of the installed sensor element. A layer of wax may change theperformance of the sensor and in effect take the installed sensor out ofcalibration.

For the chemical sensor system the calibration string may be an insertedtubing. It can be equipped with one or several reference chemical(s)that may be released down hole from the calibration string and thesystem in order to re-calibrate the installed chemical sensor. If thereadings are off, a cleaning solution can be released to remove wax,asphaltene and/or other chemicals that may foul the chemical sensinginterface and the calibration routine can be repeated.

A chemical calibration string in a simple configuration is shown in FIG.1( a). A casing string 105, often backed by cement 100, is shown insidea formation 110. A permanently installed sensor 140 is shown with a line115 carrying electrical or optical connectors running uphole to thesurface. A small opening 142 in the casing allows communication of theproduction fluids in the casing with the permanently installed sensor.In this embodiment the calibration string 120 is placed into the casingin close proximity to permanently installed sensor 140 and may have oneinjection point 130 to allow injection of fluid in the well bore. Inoperation a known fluid is injected to clean the permanently installedsensor, and the cleaning fluid is allowed to mix with the productionfluids. A second calibration liquid is then injected down thecalibration bore to calibrate the permanently installed sensors. Thecalibration string may also have a reference chemical sensor 125connected (not shown) back to the surface.

A more precise calibration string may have packers 150 surrounding acalibration string 135 that may be inflated on demand, as shown in FIG.1( b). In this embodiment the calibration string 135 is shown positionedinside of a casing 110 usually lined with cement 100 and with inflatablepackers 150 on each side of the region in which the permanentlyinstalled chemical sensor 140 is located. The permanent sensor 140 maybe deployed behind casing and may be cemented in place. A small opening142 in the casing allows communication of the production fluids in thecasing with the permanently installed sensor. In this embodimentcalibration string 135 may also have more than one port to allow fluidcirculation from a first port 155 to a second port 160. There may be one145 or possibly more reference chemical sensors in the calibrationstring, connected (not shown) back to the surface. One way of operatingthe calibration string is to inflate 2 packers, one above and one belowthe fluid ports and the reference sensor(s). Each of the ports 155 and160 may have individual lines (not shown) running back to the surfacewithin calibration string 135 in order to feed and retrieve the fluidsto the desired area between packers 150. Cleaning and calibration fluidcan now be circulated between the fluid ports as required to clean andcalibrate the sensors. The packers can then be deflated and thecalibration string can be moved to a different location.

The calibration string may have two packers and one fluid injectionport. The lower packer is then inflated and cleaning fluid is pumped sothat the fluid passes the permanently installed sensor and cleans it.Calibrated fluid can then be pumped and the second packer can be setonce a selected volume has been pumped into the area. The calibrationfluid is now trapped between the packers and both the permanentlyinstalled chemical sensor and the reference sensor in the calibrationstring will be exposed to a fluid with the same chemical concentration.

EXAMPLE 2

A strain sensing fiber must be coupled to the measurement object foraccurate measurements, and the sensing fiber must be protected to avoidmechanical damage. This is normally achieved by cabling the sensingfiber in a manner that the any strain in the cable is communicated intothe optical sensing fiber. The sensing cable is then coupled to themeasurement object by welding a sensing cable to a structure, or gluingthe sensing cable to a structure, or by cementing the sensing cable inplace. The sensing fiber must be coupled to the sensing cable foraccurate measurements, and there may be creep between the sensing cableand sensing fiber or creep between the sensing cable and the measurementobject. The creep depends on many different factors like e.g. materialselection, temperature, amount of strain the sensing configuration isexposed to and this may change over time. A strain sensor may experiencesignificant mechanical exposure during installation due to challengingwell bore conditions, and this may take the sensor out of calibrationover time due to e.g. creep as the tubing and/or casing may be left intension, torsion or compression.

For a strain sensor a mechanical system that can apply a characteristicstrain signature on one or several down-hole points can be used tocalibrate a strain sensing system. FIG. 2 shows such an embodiment. Acasing string 210 backed by cement 220 is shown inside the formation230. A calibration string 240, comprising a central arm, may have one orseveral moveable arms 250 that extends out from the calibration stringand push against the walls of casing or tubing 210. Both the casing andtubing may deform as the mechanical arms push out onto the wall of themeasurement object. As the casing or tubing deforms, the resultingstrain is captured with the permanently installed strain sensor 260,which is cemented behind casing 210. There could also be a single pointstrain sensor 265 deployed. The calibration string may have a strainsensing system embedded in the tool or there may be point sensors in thestring to measure resulting strain on the tool. The system may havepressure pads 270, 280 on the opposing side of the moveable arm togenerate a characteristic strain signature, and these pads may be usedinstead of multiple moveable arms. The calibration string may alsoinclude force-measuring pads on or in close proximity of the moveablearms so that a strain can be calculated given that the casing and tubingdimensions are well known in the well.

EXAMPLE 3

A fiber optic pressure installed sensor may experience creep between thesensing fiber and the mechanical structure that converts pressure to anoptical property that can be sensed, and this creep may take theinstalled sensor out of calibration. The single point fiber opticpressure sensor of FIG. 3 may be installed behind the casing and have apressure port to communicate pressure from inside the wellbore to thesensor. As shown in FIG. 3 a permanently installed sensor 340 withelectrical or optical conductors 342 is shown behind casing 310 and isnormally attached to the measurement object by e.g. mechanical coupling,glued, welded or cemented 305 in place along the length of the tubulardown-hole structure 310 such that any movement of the tubular structureis coupled to the sensor.

This re-calibration can be done as follows. A calibration string 335with a pressure sensing system 345 using multiple packers 350 can beused to isolate a zone where a permanently installed pressure sensor 340is installed. The packer(s) can be used to isolate the zone, and theformation pressure can be used as a calibration pressure and acomparison can be made between the permanently installed sensor 340 andthe reference pressure sensor 345 in the calibration string. Thecalibration string may have means of applying a controlled pressure aswell by applying pressure via an opening 338 in the calibration stringbetween the packers.

A simple calibration string can be used without any packers if formationpressure or tubing/casing pressure is used for calibration. Depthcorrelation is normally done by measuring the length of calibrationstring that has been lowered in the well. A more accurate depthcalibration can be done using permanently deployed DTS and/or DAScombined with thermal and/or acoustic events in the calibration string.An example of a thermal event could be electrical heaters, fluidinjection in the calibration string where a difference in temperature isdetected using the permanently deployed DTS system. Examples of acousticevents could be a battery operated device emitting a tone of a certainfrequency, and the location would be measured as the peak location ofthe acoustic amplitude of the tone.

EXAMPLE 4

A Distributed Temperature Sensing (DTS) system may have fiber-agingdown-hole due to temperature and/or chemical exposure causinginaccuracies in the measurements. This effect can largely be mitigatedin Distributed Temperature Sensing (DTS) systems using dual lasertechnology, but re-calibration can in some cases improve the accuracy oftemperature readings.

This re-calibration can be done as follows. A calibration string withmeans of measure temperature accurate can be inserted into the wellborefor comparison between the permanently installed sensor and thereference sensor. The calibration string may have means of changing thedown-hole temperature both for depth calibration purposes and fortemperature calibration purposes. The temperature change can be madeusing electrical, chemical or mechanical means like inserting fluidand/or steam through a conduit in the calibration string. Thecalibration string could be a well-calibrated optical fiber sensorpumped into a conduit, or a small OD cable with optical fibers present.The calibration string can also be a stiff cable that can be pushed intoa conduit or well. The reference sensor in the calibration string can beelectrical (thermo-couples etc.) or optical, and optical configurationsinclude e.g. distributed temperature sensing systems based on Raman,Rayleigh or Brillouin effects, and/or single point sensors based on FBGsensors, Fabry-Perot sensors or other means of measuring temperature.

An embodiment for doing this is illustrated in FIG. 4, which utilizes atechnique used in DTS installations in Steam Assisted Gravity Drainagewells used in the Canadian oil sands operations where it is common topump optical fibers into conduits for temperature sensing. A conduit 430(often ¼″ metal tubes) is shown deployed in a double endedconfiguration. The fluid flow goes down hole in conduit 430 usually tothe bottom of the well where a Turn-Around-Sub (TAS) 450 is installed,and the fluid comes up the other conduit 440. The optical fiber, whichbecomes the permanently installed sensor, is deployed in the fluid flowand the distributed forces acting on the fiber and drags into theconduit. The fiber can either be deployed in a single ended fashionwhere the fiber stops at TAS 450, or it can be pumped all the way to thesurface in a double-ended configuration. A second fiber can be pumped inon top of the first fiber, although it is more challenging to get thesecond fiber to full depth. The second fiber can be used as acalibration string, either as a distributed system or with single pointsensors suitably attached to the cable. The calibration string can alsobe a stiff cable with thermo-couples and/or optical fibers fordistributed and/or point temperature sensors. The stiff cable can bepushed into the return conduit 440 in the case of a single endedinstallation. This method uses a reference sensor in the cable, and thecalibration is done to the well bore temperature. Different temperaturesmay occur during steam injection and when the well is put on production,and the variation over temperature can be used to achieve a solidcalibration.

EXAMPLE 5

A Distributed Acoustic Sensing (DAS) system may have different couplingbetween the fiber and the formation due to e.g. cement around thesensing cable. The acoustic amplitude may vary, and it may beadvantageous to have a better understanding of where you have goodcoupling to the formation and where there may be less coupling andtherefore lower signals.

This re-calibration can be done as follows. As shown in FIG. 5, acalibration string 520 can be deployed into the well bore within casing510 in close proximity to the permanently installed DAS system 515. TheDAS sensing cable 515 may be permanently cemented in place between thecasing 510 and the formation 550, and normally run to the bottom of thewell. Calibration string 520 can be equipped with a calibratednoisemaker 530 and can be inserted in the well and used to apply acharacteristic acoustic signature on one or several downhole points inclose proximity to installed sensor 515 and thereby log the acousticsignature of the DAS system. A thermal point event can also be used fordepth calibration purposes when there is a DTS system present in thesame sensing cable as the DAS fiber.

EXAMPLE 6

Seismic sensors may be permanently installed in a well, and cemented inplace behind casing, or attached to tubing where coupling to the well isdone mechanically or magnetically. It is however impossible to know howwell the installed sensor is coupled to the formation, and the seismicsignal amplitude is directly proportional to how well the installedsensor is coupled to the formation. Seismic sensors may also have movingparts and the orientation may be un-known.

This re-calibration can be done as follows. Referring to FIG. 6representing a formation 630 a permanently installed seismic sensor 640is attached to the outside of casing 610, possibly in a cement 625matrix, with communication back to the surface via tubing 650. Acalibration string 620 with a vibration source 670 can be inserted inthe well and located in close proximity of the permanently installedseismic sensor 640. The calibration string may have mechanical couplingto the tubular structure where the seismic sensors are located. Examplesof mechanical coupling could be a spring-loaded locking arm, amechanical packer, or a bow-spring type device that mechanically couplesthe calibration string with the tubular structure where the seismicsensors are located. As shown in FIG. 6 the mechanically coupling isaccomplished via locking arm 680, pressed against the casing or tubing610. The vibration of vibration source 670 will allow calibration andhealth check of the fiber optic seismic sensors and can also be used toverify sensor orientation assuming the calibration string is properlyequipped.

The calibration string may be designed to couple both shear and pressurewaves through a mechanical arm or other mechanical coupling device orthe calibration string may sit in a fluid without mechanical couplingwhere pressure waves are mainly used for calibration purposes.

EXAMPLE 7

An electromagnetic sensing system can be permanently installed in awell.

A calibration string can be inserted in the well in close proximity tothe installed electromagnetic sensing system that contains smallpermanent magnets or electrical coils that can be used to generate acharacteristic magnetic field signature. The calibration string can thenbe used for calibration and health check of the installedelectromagnetic sensing system. FIG. 7 illustrates such a system. A wellcasing 710, possibly backed up by a layer of cement 705 lies within theformation 700. A calibration string 720 has been installed inside wellcasing 710 near a permanently installed electromagnetic sensing system740, which is in communication with the surface via cable 715. Thepermanently installed electromagnetic sensing system 740 may be incement 705 behind the casing. The calibration string 720 has installedeither small permanent magnets or electrical coils 725. These are usedto generate a characteristic magnetic signature and electromagneticsensor 710 can be calibrated against that.

Although certain embodiments and their advantages have been describedherein in detail, it should be understood that various changes,substitutions and alterations could be made without departing from thecoverage as defined by the appended claims. Moreover, the potentialapplications of the disclosed techniques is not intended to be limitedto the particular embodiments of the processes, machines, manufactures,means, methods and steps described herein. As a person of ordinary skillin the art will readily appreciate from this disclosure, otherprocesses, machines, manufactures, means, methods, or steps, presentlyexisting or later to be developed that perform substantially the samefunction or achieve substantially the same result as the correspondingembodiments described herein may be utilized. Accordingly, the appendedclaims are intended to include within their scope such processes,machines, manufactures, means, methods or steps.

I claim:
 1. A downhole in-situ recalibration device for use inre-calibrating an installed downhole seismic sensor comprising: a. adownhole calibration string associated with seismic sensing; b. whereinsaid calibration string contains a vibration source used to apply acharacteristic seismic signature on one or several downhole points inclose proximity to said installed downhole seismic sensor.
 2. Thedownhole in-situ recalibration device for use in re-calibrating aninstalled downhole seismic sensor of claim 1 wherein the installeddownhole seismic sensor is coupled to the outside of a well casing andthe downhole calibration string is inserted into the wellbore.
 3. Thedownhole in-situ recalibration device for use in re-calibrating aninstalled downhole seismic sensor of claim 1 wherein the downholecalibration string is mechanically coupled to the wellbore casing ortubing after insertion into the wellbore.
 4. The downhole in-siturecalibration device for use in re-calibrating an installed downholeseismic sensor of claim 3 wherein the calibration string is mechanicallycoupled to the wellbore casing or tubing by locking arms pressed againstthe casing or tubing of the wellbore.
 5. The downhole in-siturecalibration device for use in re-calibrating an installed downholeseismic sensor of claim 3 wherein the calibration string is mechanicallycoupled by use of a mechanical packer.
 6. The downhole in-siturecalibration device for use in re-calibrating an installed downholeseismic sensor of claim 3 wherein the calibration string is mechanicallycoupled by a bow-spring device that expands to mechanically couple thecalibration string to the wellbore.
 7. The downhole in-siturecalibration device for use in re-calibrating an installed downholeseismic sensor of claim 1 wherein the characteristic seismic signatureof the calibration string has a known orientation.
 8. A method forin-situ recalibration of an installed seismic sensor in a downholesensing system in hydrocarbon wells comprising: a. Inserting acalibration string associated with seismic sensing in the wellbore ofthe hydrocarbon well in close proximity to said installed seismicsensor; wherein the calibration string contains a vibration source thatcan be used to apply a characteristic seismic signature on one or moredownhole points in close proximity to said installed downhole seismicsensor; b. mechanically coupling the calibration string to the wellbore;c. using the calibration string to apply characteristic signatures atthe one or more downhole points that are used to re-calibrate theinstalled seismic sensor.
 9. The method for in-situ recalibration of aninstalled seismic sensor in a downhole sensing system in hydrocarbonwells of claim 8 wherein the calibration string is mechanically coupledto the wellbore casing or tubing by locking arms pressed against thecasing or tubing of the wellbore.
 10. The method for in-siturecalibration of an installed seismic sensor in a downhole sensingsystem in hydrocarbon wells of claim 8 wherein the calibration string ismechanically coupled to the wellbore casing or tubing by use of amechanical packer.
 11. The method for in-situ recalibration of aninstalled seismic sensor in a downhole sensing system in hydrocarbonwells of claim 8 wherein the calibration string is mechanically coupledto the wellbore casing or tubing by a bow-spring device that expands tomechanically couple the calibration string to the wellbore.
 12. Themethod for in-situ recalibration of an installed seismic sensor in adownhole sensing system in hydrocarbon wells of claim 8 wherein thecharacteristic seismic signature of the calibration string has a knownorientation.